Author: Enno

How much oil have operators already produced from their existing wells, and how much can we still expect from them?

To answer these, and related questions, I have created the presentation above. It contains three main overviews, which you can see by clicking on the “tabs” on top of it:

Projected Production. Here you can see the oil production of 46408 horizontal wells that started production before 2016. The view is split at January 2016, after which the production has been projected using a method I will explain below.

Production Profiles. Here you can see the actual, and projected production profiles for all wells, on which the first and third overview are based. You can use the “basin”, “operator”, and “first flow” selections to narrow down the selected wells. With the “show production” selection, you can see for the selected wells the actual (historical) production, the projected production, or both.

Ultimate Return. This overview shows for each operator the amount of oil already produced from its wells, and the amount that is estimated to be produced from its wells in the future. Also, it shows for each basin, the estimated ultimate return (EUR), including the amount of oil that can be expected each year on production.

All overviews use the same 46408 horizontal wells that started production before 2016.

Just to be sure, this presentation doesn’t show what actual US shale production will be in the future (I don’t know); as we’ve seen in the past, with abundant capital available, large increases are possible. Future production is simply unknowable. Still, by using all available production data so far, and the assumption that well behavior will not change much, I belief a reasonable estimation can be performed of what existing, producing, shale wells are going to produce. That is what this attempt is all about.

This is the first time I’ve put up this presentation, and that increases the chance somewhat that there are still some issues. If you find anything strange, please let me know.

For those interested in details, I will now explain the method I used to make these projections in some more detail.

Method

I’ve estimated the future output of each individual well, for which I had a complete production history (= 46408 wells). The key assumption on which the method is based is that the future behavior of wells will be similar as the behavior we’ve seen in the past. As I’ve shown in the previous posts, it does strongly appear that wells behave rather similarly as past wells, especially after the initial 12-18 months on production.

For each basin, and for each well age (month on production), I’ve clustered wells by their actual production rate. For each of these clusters, I’ve determined the average actual decline rate. In order to make an individual well projection, I determined the age for each well and to which cluster it belongs, and then applied the related historical decline rate.

For far-out months, for which very limited data exists, I’ve used terminal decline rates depending on the basin (8% for the Bakken, and 10% for other basins). Also, I used an economical cut-off of 10 bo/d for Bakken, and 6 bo/d for non-Bakken wells, after which the wells stop producing. I think that these are reasonable estimates, but will not try to defend them. Instead, by explaining in some detail the method used, I hope that you can understand the results, and allow you, based on your own knowledge and expectations, whether you want to adjust the results in some way.

Note that different estimates for these terminal decline rates, and economical cut-offs will not greatly affect the outcome, as most of the production happens in the first several years, and for this period extensive data already exists.

Some weaknesses of this method:

Decline rates are estimated based on all the wells in the basin, and not for the area (county/field/formation/depth). Basin-wide results will therefore be more accurate than more local results.

I have no information on the completion methods used for each well, and therefore completely ignore this, while acknowledging that this may strongly effect individual well returns.

Only the latest known production rate is used to determine which decline rate should be applied. A better way is to also use the production trajectory of the past several months.

I will probably make further enhancements to this method, and the parameters, in the future, although I don’t expect significant differences from this result.

I’ve tried to exclude the effect of refracing, by excluding production histories after an apparent refracing event. As some of these legacy wells are likely to be refraced in the future, future production will be a little higher (a few percent).

Note that for wells for which I have accurate production data after January 2016, I’ve used that, instead of estimating it.

Gas production is completely excluded from this presentation.

On Friday afternoon I plan another update on North Dakota.

====BRIEF MANUAL====

The above presentation has many interactive features:

You can click through the blocks on the top to see the slides.

Each slide has filters that can be set, e.g. to select individual or groups of operators. You can first click “all” to deselect all items. You have to click the “apply” button at the bottom to enforce the changes. After that, click anywhere on the presentation.

Tooltips are shown by just hovering the mouse over parts of the presentation.

You can move the map around, and zoom in/out.

By clicking on the legend you can highlight selected items, and include or exclude categories.

Note that filters have to be set for each tab separately.

The operator who currently owns the well is designated by “operator (current)”. The operator who operated a well in a past month is designated by “operator (actual)”. This distinction is useful when the ownership of a well changed over time.

If you have any questions on how to use the interactivity, or how to analyze specific questions, please don’t hesitate to ask.